EP2848298B1

EP2848298B1 - Composite amine absorbing solution and method for removing co2, h2s, or both

Info

Publication number: EP2848298B1
Application number: EP13788078.7A
Authority: EP
Inventors: Hiroshi Tanaka; Hiromitsu Nagayasu; Takuya Hirata; Tsuyoshi Oishi; Takashi Kamijo
Original assignee: Kansai Electric Power Co Inc; Mitsubishi Heavy Industries Engineering Ltd
Current assignee: Kansai Electric Power Co Inc; Mitsubishi Heavy Industries Engineering Ltd
Priority date: 2012-05-11
Filing date: 2013-04-25
Publication date: 2018-12-26
Anticipated expiration: 2033-04-25
Also published as: US20150132207A1; EP2848298A1; AU2013258901A1; JP5986796B2; JP2013236987A; AU2013258901B2; WO2013168588A1; US10137407B2; CA2872593C; EP2848298A4; CA2872593A1

Description

Field

The present invention relates to a complex amine absorbent and to a device and a method for removing one or both of CO₂ and H₂S.

Background

The greenhouse effect due to CO₂ has recently been pointed out as a cause of global warming, and international measures to address the greenhouse effect are urgently needed to protect the global environment. Sources of CO₂ emissions are present in all areas of human activity in which fossil fuel is combusted, and the demand for reducing CO₂ emissions tends to further increase. To meet the demand in power generation facilities such as thermal power plants that use a large amount of fossil fuel, intensive research has been conducted on a method of removing and recovering CO₂ in flue gas from a boiler by bringing the flue gas into contact with an amine-based CO₂ absorbent and on a method of storing recovered CO₂ with no emissions to the air. One process used to remove and recover CO₂ in flue gas using such a CO₂ absorbent described above includes the steps of bringing the flue gas into contact with the CO₂ absorbent in an absorber, heating the absorbent containing CO₂ absorbed therein in a regenerator to release CO₂ and regenerate the absorbent, and recirculating the regenerated absorbent into the absorber to reuse the absorbent (see, for example, Patent Literature 1).
With the method of absorbing, removing, and recovering CO₂ in CO₂-containing gas such as flue gas using the above-described CO₂ absorbent and process, since the process is installed additionally in a combustion facility, it is necessary to reduce the operating cost of the process as much as possible. Particularly, the regeneration step in the above process consumes a large amount of thermal energy, and therefore the energy used in the process must be reduced as much as possible.
In one prior proposal, part of a semi-lean solution is drawn off from a regenerator to the outside. The drawn semi-lean solution exchanges heat with a lean solution in a heat exchanger and then exchanges heat with steam-condensed water in another heat exchanger. The resultant semi-lean solution is returned to a position downward of the drawn-off position. The temperature of the semi-lean solution supplied to the lower side of the regenerator is increased, and the amount of steam consumed is thereby reduced (see, for example, Patent Literature 2 (embodiment 8, FIG. 17)).
Regarding CO₂ absorbents, in order to improve the performance thereof, absorbents contributing the improvement in their absorption performance have been proposed (Patent Literatures 3 and 4).

Citation List

Patent Literature

Patent Literature 1: Japanese Laid-open Patent Publication No. 7-51537
Patent Literature 2: Japanese Patent No. 4690659
Patent Literature 3: Japanese Laid-open Patent Publication No. 2008-13400
Patent Literature 4: Japanese Laid-open Patent Publication No. 2008-307519

Summary

Technical Problem

Important performance of a CO₂ absorbent includes not only its absorption performance but also its releasing ability when the absorbent is regenerated. One current task is to propose an absorbent having good regeneration performance as well as improved absorption performance that has been extensively studied.
As described above, steam is necessary to recover CO₂ from flue gas. Therefore, to achieve energy saving by using a small amount of water vapor while a desired amount of CO₂ is recovered, there is a strong demand for an absorbent having not only an absorption ability but also a regeneration ability, for the purpose of reducing operating cost. US20100105551 and WO2011082807 do not solve the problem.
In view of the foregoing problems, it is an object of the present invention to provide a complex amine absorbent having not only an absorption ability but also a regeneration ability and a device and a method for removing one or both of CO₂ and H₂S.

Solution to Problem

This aim is accomplished according to what is stated in the accompanying claims.
The primary amine having high steric hindrance is at least one of 2-amino-1-propanol, 2-amino-1-butanol, 2-amino-3-methyl-1-butanol, 1-amino-2-propanol, 1-amino-2-butanol, and 2-amino-2-methyl-1-propanol.
The complex amine absorbent further including any one of at least one amine selected from linear poly primary and secondary amines and at least one amine selected from cyclic polyamines.
The linear poly primary and secondary amines are ethylenediamine, N,N'-dimethylethylenediamine, N,N'-diethylethylenediamine, and N,N'-dimethylpropanediamine, andvthe cyclic polyamines are piperazine, 1-methylpiperazine, 2-methylpiperazine, 2,5-dimethylpiperazine, 1-(2-aminoethyl)piperazine, and 1-(2-hydroxyethyl)piperazine.
The complex amine absorbent is circulated and reused in an absorbing-removing facility including an absorber for absorbing one or both of CO₂ and H₂S in the gas and a regenerator in which the one or both of CO₂ and H₂S absorbed are released to regenerate the absorbent, a pressure inside the regenerator is 130 to 200 kPa (absolute pressure), an absorption temperature in the absorber is 30 to 80°C, and a regeneration temperature in the regenerator is 110°C or higher.
There is provided the device for removing one or both of CO₂ and H₂S, the device comprising: an absorber for removing one or both of CO₂ and H₂S by bringing a gas containing one or both of CO₂ and H₂S in contact with an absorbent; and a regenerator for regenerating a solution containing the one or both of CO₂ and H₂S absorbed therein, the solution regenerated by removing the one or both of CO₂ and H₂S in the regenerator being reused in the absorber, wherein the complex amine absorbent according to what described in the claims is used.
There is also provided a method of removing one or both of CO₂ and H₂S, the method comprising: bringing a gas containing one or both of CO₂ and H₂S in contact with an absorbent to remove the one or both of CO₂ and H₂S; regenerating a solution containing one or both of CO₂ and H₂S absorbed therein; and reusing, in an absorber, the solution regenerated by removing the one or both of CO₂ and H₂S in a regenerator, wherein
the complex amine absorbent according to what described in the claims is used to remove the one or both of CO₂ and H₂S.

Advantageous Effects of Invention

The present invention is well described in what is stated in claim 1.

Brief Description of Drawings

FIG. 1 is a schematic diagram illustrating the configuration of a CO₂ recovery unit according to a first embodiment.
FIG. 2 is a graph showing the relation between relative saturated CO₂ absorption capacity and the weight ratio of a sterically hindered primary amine to MEA in Test Example 1 when the total concentration of amines is 45% by weight.
FIG. 3 is a graph showing the relation between relative saturated CO₂ absorption capacity and the weight ratio of a sterically hindered primary amine to MEA in Test Example 1 when the total concentration of amines is 35% by weight.
FIG. 4 is a graph showing the relation between relative saturated CO₂ concentration difference and the weight ratio of AMP to MEA in Test Example 2 when the total concentration of amines is 35% by weight.
FIG. 5 is a graph showing the relation between relative saturated CO₂ concentration difference and the weight ratio of AMP to MEA in Test Example 2 when the total concentration of amines is 40% by weight.
FIG. 6 is a graph showing the relation between relative saturated CO₂ concentration difference and the weight ratio of AMP to MEA in Test Example 2 when the total concentration of amines is 45% by weight.
FIG. 7 is a graph showing the relation between reaction rate indicator and the weight ratio of a polyamine to a primary amine in Test Example 3.

Description of Embodiments

The present invention will next be described in detail with reference to the drawings. However, the present invention is not limited by this embodiment Components in the following embodiments include those that can be easily devised by persons skilled in the art or that are substantially the same.

Embodiments

A complex amine absorbent according to the invention is disclosed in claim 1.
The total concentration of amine in the complex amine absorbent is 30 to 70% by weight and more preferably 40 to 70% by weight.
In the present invention, 1) monoethanolamine (MEA) and 2) the primary amine having high steric hindrance are dissolved in water to prepare the absorbent. These amines are entangled in a complex manner, and the synergistic effect of these amines provides high ability to absorb one or both of CO₂ and H₂S and high ability to release absorbed CO₂ or H₂S during regeneration of the absorbent, so that the amount of water vapor used in a CO₂ recovery facility during regeneration of the absorbent can be reduced.
The primary amine having high steric hindrance is any one of 2-amino-1-propanol (2A1P), 2-amino-1-butanol (2A1B), 2-amino-3-methyl-1-butanol (AMB), 1-amino-2-propanol (1A2P), 1-amino-2-butanol (1A2B), and 2-amino-2-methyl-1-propanol (AMP).
A combination of the above amines may be used.
When a combination of amines is used, it is preferable to use an absorbent containing 2-amino-2-methyl-1-propanol (AMP) as a base amine and another amine added thereto.
The total concentration of amines in the complex amine absorbent is 30 to 70% by weight. This is because, when the total concentration of amines falls outside this range, the complex amine absorbent does not favorably function as an absorbent.
The weight ratio of 2) the primary amine having high steric hindrance to 1) monoethanolamine (MEA) is within the range of 0.3 to 2.5, preferably within the range of 0.3 to 1.2, and more preferably within the range of 0.3 to 0.7.
This is because, as described in Test Examples later, absorption performance becomes lower than reference absorption performance, i.e., the absorption performance when the concentration of MEA is 30% by weight, which is a concentration generally used in conventional absorbents.
The above ratio is changed according to the total amine concentration. When the total amine concentration is 30% by weight, the ratio is a value close to 0.3.
Any one of at least one amine selected from linear poly primary and secondary amines and at least one selected from cyclic polyamines is further contained as an assistant.
The addition of the assistant improves the rate of reaction, so that energy saving can be achieved.
The linear poly primary and secondary amines are ethylenediamine (EDA), N,N'-dimethylethylenediamine (DMEDA), N,N'-diethylethylenediamine (DEEDA), and N,N'-dimethylpropanediamine (DMPDA), and the cyclic polyamines are piperazine (PZ), 1-methylpiperazine (1MPZ), 2-methylpiperazine (2MPZ), 2,5-dimethylpiperazine (DMPZ), 1-(2-aminoethyl)piperazine (AEPRZ), and 1-(2-hydroxyethyl)piperazine (HEP).
Preferably, the weight ratio of "at least one amine selected from the linear poly primary and secondary amines or at least one amine selected from the cyclic polyamines" to "the complex primary amine absorbent containing monoethanolamine and at least one amine selected from primary amines having high steric hindrance" (the weight ratio of the polyamine / the complex primary amine) is 1 or less.
In the present invention, absorption temperature in an absorber during contact with flue gas containing CO₂ etc. is generally within the range of preferably 30 to 80°C. If necessary, an anti-corrosive agent, an anti-degradant, etc. are added to the absorbent used in the present invention.
In the present invention, regeneration temperature in a regenerator in which CO₂ etc. are released from the absorbent containing CO₂ etc. absorbed therein is preferably 110°C or higher when the pressure inside the regenerator is 130 to 200 kPa (absolute pressure). This is because, when regeneration is performed below 110°C, the amount of the absorbent circulating in the system must be increased, and this is not preferred in terms of regeneration efficiency.
More preferably, regeneration is performed at 120°C or higher.
Examples of the gas treated by the present invention include coal gasification gases, synthesis gases, coke-oven gases, petroleum gases, and natural gases, but the gas treated is not limited thereto. Any gas may be used so long as it contains an acid gas such as CO₂ or H₂S.
No particular limitation is imposed on a process that can be used in a method of removing one or both of CO₂ and H₂S in the gas in the present invention. An example of a removing device for removing CO₂ will be described with reference to FIG. 1.
FIG. 1 is a schematic diagram illustrating the configuration of a CO₂ recovery unit. As shown in FIG. 1, a CO₂ recovery unit 12 includes: a flue gas cooling unit 16 for cooling, with cooling water 15, flue gas 14 containing CO₂ and O₂ discharged from an industrial combustion facility 13 such as a boiler or a gas turbine; a CO₂ absorber 18 including a CO₂ recovery section 18A for removing CO₂ from the flue gas 14 by bringing the cooled flue gas 14 containing CO₂ into contact with a CO₂ absorbent 17 (hereinafter may be referred to as an "absorbent") that absorbs CO₂; and an absorbent regenerator 20 for regenerating the CO₂ absorbent by causing the CO₂ absorbent 19 containing CO₂ absorbed therein (hereinafter, this absorbent may also be referred to as a "rich solution") to release CO₂. In the CO₂ recovery unit 12, the regenerated CO₂ absorbent 17 from which CO₂ has been removed in the absorbent regenerator 20 (hereinafter, this absorbent may also be referred to as a "lean solution") is reused in the CO₂ absorber 18 as the CO₂ absorbent.
In FIG. 1, reference numeral 13a represents a flue gas duct, 13b represents a stack, and 34 represents steam-condensed water. The CO₂ recovery unit may be retrofitted to an existing flue gas source to recover CO₂ therefrom or may be installed together with a new flue gas source. An open-close damper is disposed in a line for the flue gas 14 and is opened during operation of the CO₂ recovery unit 12. When the flue gas source is in operation but the operation of the CO₂ recovery unit 12 is stopped, the damper is set to be closed.
In a CO₂ recovery method using the CO₂ recovery unit 12, the flue gas 14 containing CO₂ and supplied from the industrial combustion facility 13 such as a boiler or a gas turbine is first increased in pressure by a flue gas blower 22, then supplied to the flue gas cooling unit 16, cooled with the cooling water 15 in the flue gas cooling unit 16, and then supplied to the CO₂ absorber 18.
In the CO₂ absorber 18, the flue gas 14 comes into countercurrent contact with the CO₂ absorbent 17 serving as an amine absorbent according to this embodiment, and the CO₂ in the flue gas 14 is absorbed by the CO₂ absorbent 17 through a chemical reaction.
The CO₂-removed flue gas from which CO₂ has been removed in the CO₂ recovery section 18A comes into gas-liquid contact with circulating wash water 21 containing the CO₂ absorbent and supplied from a nozzle in a water washing section 18B in the CO₂ absorber 18, and the CO₂ absorbent 17 entrained in the CO₂-removed flue gas is thereby recovered. Then a flue gas 23 from which CO₂ has been removed is discharged to the outside of the system.
The rich solution, which is the CO₂ absorbent 19 containing CO₂ absorbed therein, is increased in presser by a rich solution pump 24, heated by the lean solution, which is the CO₂ absorbent 17 regenerated in the absorbent regenerator 20, in a rich-lean solution heat exchanger 25, and then supplied to the absorbent regenerator 20.
The rich solution 19 released into the absorbent regenerator 20 from its upper portion undergoes an endothermic reaction due to water vapor supplied from the bottom portion, and most CO₂ is released. The CO₂ absorbent that has released part or most of CO₂ in the absorbent regenerator 20 is referred to as a semi-lean solution. The semi-lean solution becomes the CO₂ absorbent (lean solution) 17 from which almost all CO₂ has been removed when the semi-lean solution reaches the bottom of the absorbent regenerator 20. Part of the lean solution 17 is superheated by water vapor 27 in a regeneration superheater 26 to supply water vapor to the inside of the regenerator 20.
CO₂-entrained gas 28 accompanied by water vapor produced from the rich solution 19 and semi-lean solution in the absorbent regenerator 20 is discharged from the vertex portion of the absorbent regenerator 20. The water vapor is condensed in a condenser 29, and water is separated by a separation drum 30. CO₂ gas 40 is discharged to the outside of the system, compressed by a separate compressor 41, and then recovered. A compressed and recovered CO₂ gas 42 passes through a separation drum 43 and then injected into an oil field using Enhanced Oil Recovery (EOR) or reserved in an aquifer to address global warming.
A reflux water 31 separated from the CO₂-entrained gas 28 accompanied by water vapor in the separation drum 30 and refluxed therethrough is supplied to the upper portion of the absorbent regenerator 20 through a reflux water circulation pump 35 and also supplied as the circulating wash water 21.
The regenerated CO₂ absorbent (lean solution) 17 is cooled by the rich solution 19 in the rich-lean solution heat exchanger 25, then increased in pressure by a lean solution pump 32, cooled in a lean solution cooler 33, and then supplied to the CO₂ absorber 18. In the embodiment, their outlines have been described, and part of attachments is omitted in the description.
Preferred Test Examples showing the effects of the present invention will next be described, but the present invention is not limited thereto.

[Test Example 1]

An unillustrated absorption device was used for absorption of CO₂. FIGS. 2 and 3 are graphs showing the relation between relative saturated CO₂ absorption capacity and the weight ratio of a sterically hindered primary amine to MEA in Test Example 1.

A Comparative Example is a conventionally used absorbent containing monoethanolamine (MEA) alone.
An absorbent containing MEA at a concentration of 30% by weight was used as a reference absorbent, and a relative saturated CO₂ absorption capacity was shown.
The relative saturated CO₂ absorption capacity is determined as follows.
Relative saturated CO₂ absorption capacity = saturated CO₂ absorption capacity of an absorbent in the subject application (at a concentration in the Test Example) / saturated CO₂ absorption capacity of the MEA absorbent (30 wt%)

In Test Example 1, one of 2-amino-1-propanol (2A1P), 2-amino-1-butanol (2A1B), 2-amino-3-methyl-1-butanol (AMB), 1-amino-2-propanol (1A2P), and 2-amino-2-methyl-1-propanol (AMP) was used as the primary amine having high steric hindrance at a mixing ratio shown in a lower part of FIG. 2. The amines were dissolved in water and mixed to prepare respective absorbents.
The total amine concentration in Test Example 1 was 45% by weight.
The absorption conditions in this test were 40°C and 10 kPa CO₂.
The results are shown in FIG. 2.
In FIG. 2, the saturated CO₂ absorption capacity of the 30 wt% MEA absorbent was used as a reference value of "1," and the relative saturated CO₂ absorption capacity of each absorbent was shown.
As shown in FIG. 2, for all the four primary amines having high steric hindrance (2-amino-1-propanol (2A1P), 2-amino-1-butanol (2A1B), 1-amino-2-propanol (1A2P), and 2-amino-2-methyl-1-propanol (AMP)), the relative saturated CO₂ absorption capacity was higher than the reference value "1," and the absorption performance was found to be good.
Of these, 2-amino-2-methyl-1-propanol (AMP), in particular, showed a very high value for the absorption performance.
As shown in FIG. 3, even when the total amine concentration was changed from 45% by weight to 35% by weight, the relative saturated CO₂ absorption capacity of the amine solution using a combination of monoethanolamine (MEA) and 2-amino-2-methyl-1-propanol (AMP) was higher than a reference value of "1," and the absorption performance was found to be good.

[Test Example 2]

A Comparative Example is a conventionally used absorbent containing monoethanolamine (MEA) alone.
An absorbent containing MEA at a concentration of 30% by weight was used as a reference absorbent, and a relative saturated CO₂ concentration difference was shown.
The relative saturated CO₂ concentration difference is determined as follows. $\begin{array}{l} {Relative saturatedCO}_{2} concentration difference = \\ {saturedCO}_{2} concentration difference of an absorbent in \\ the subject application (at a concentration in the Test \\ Example) / {saturatedCO}_{2} concentration difference of the \\ MEA absorbent (30 % by weight) \end{array}$
The saturated CO₂ concentration difference is determined as follows.
Saturated CO₂ concentration difference = saturated CO₂ concentration under absorption conditions - saturated CO₂ concentration under recovery conditions

In Test Example 2, 2-amino-2-methyl-1-propanol (AMP) was used as the primary amine having high steric hindrance at a mixing ratio shown in a lower part of each of FIGS. 4 to 6. The amines were dissolved in water and mixed to prepare respective absorbents.
The total amine concentration in Test Example 2-1 was 35% by weight (see FIG. 4).
The total amine concentration in Test Example 2-2 was 40% by weight (see FIG. 5).
The total amine concentration in Test Example 2-3 was 45% by weight (see FIG. 6).
The absorption conditions in the test were 40°C and 10 kPa CO₂.
The recovery conditions were 120°C and 10 kPa CO₂.
The results are shown in FIGS. 4 to 6. FIG. 4 is a graph showing the relation between the relative saturated CO₂ concentration difference and the weight ratio of AMP to MEA in Test Example 2-1 in which the total amine concentration is 35% by weight. FIG. 5 is a graph showing the relation between the relative saturated CO₂ concentration difference and the weight ratio of AMP to MEA in Test Example 2-2 in which the total amine concentration is 40% by weight. FIG. 6 is a graph showing the relation between the relative saturated CO₂ concentration difference and the weight ratio of AMP to MEA in Test Example 2-3 in which the total amine concentration is 45% by weight.
In FIG. 4 to FIG. 6, the saturated CO₂ absorption capacity of the 30 wt% MEA absorbent was used as a reference value of "1," and the relative saturated CO₂ absorption capacity of each absorbent was shown.
As shown in FIG. 4, in Test Example 2-1 in which 2-amino-2-methyl-1-propanol (AMP) was used as the primary amine having high steric hindrance, the relative saturated CO₂ concentration difference was higher than a reference value of "1" when the weight ratio was about 0.5 or less, and the absorption performance was found to be good.
As shown in FIG. 5, in Test Example 2-2 in which 2-amino-2-methyl-1-propanol (AMP) was used as the primary amine having high steric hindrance, the relative saturated CO₂ concentration difference was higher than a reference value of "1" when the weight ratio was about 1.2 or less, and the absorption performance was found to be good.
When the weight ratio was about 0.7 or less, the relative saturated CO₂ concentration difference was significantly higher than a reference value of "1" (an improvement of about 10%), and the absorption performance was found to be better.
As shown in FIG. 6, in Test Example 2-3 in which 2-amino-2-methyl-1-propanol (AMP) was used as the primary amine having high steric hindrance, the relative saturated CO₂ concentration difference was higher than a reference value of "1" when the weight ratio was about 2.5 or less, and the absorption performance was found to be good.

[Test Example 3]

A Comparative Example is a conventionally used absorbent containing monoethanolamine (MEA) alone.
An absorbent containing MEA at a concentration of 30% by weight was used as a reference absorbent, and a reaction rate indicator was shown.
The reaction rate indicator is determined as follows.
Reaction rate indicator = reaction rate index of an absorbent in the subject application (at a concentration in the Test Example) / reaction rate index of the MEA absorbent (30% by weight)
The reaction rate index is determined as follows. $Reaction rate index = {(reaction rate constant \times amine concentration \times {diffusion coefficient ofCO}_{2})}^{0.5}$

In Test Example 3, 2-amino-2-methyl-1-propanol (AMP) was used as the primary amine having high steric hindrance, and a polyamine used as an assistant was added at a mixing ratio shown in a lower part of FIG. 7. These were dissolved in water and mixed to prepare an absorbent.
Ethylenediamine (EDA), N,N'-dimethylethylenediamine (DMEDA), N,N'-diethylethylenediamine (DEEDA), propanediamine (PDA), N,N'-dimethylpropanediamine (DMPDA), piperazine (PZ), 1-methylpiperazine (1MPZ), 2-methylpiperazine (2MPZ), 2,5-dimethylpiperazine (DMPZ), 1-(2-aminoethyl)piperazine (AEPRZ), and 1-(2-hydroxyethyl)piperazine (HEP) were used as the assistant added.
In Test Example 3, the total amine concentration was 40% by weight.
The absorption conditions in this test were 40°C and 10 kPa CO₂.
The results are shown in FIG. 7. FIG. 7 is a graph showing the relation between the reaction rate indicator and the weight ratio of a polyamine to the primary amine in Test Example 3.
In FIG. 7, the reaction rate index of the 30 wt% MEA absorbent was used as a reference vale of "1," and the reaction rate indicator of each absorbent was shown.
As shown in FIG. 7, when any of the assistants (ethylenediamine (EDA), N,N'-dimethylethylenediamine (DMEDA), N,N'-diethylethylenediamine (DEEDA), N,N'-dimethylpropanediamine (DMPDA), piperazine (PZ), 1-methylpiperazine (1MPZ), 2-methylpiperazine (2MPZ), 2,5-dimethylpiperazine (DMPZ), 1-(2-aminoethyl)piperazine (AEPRZ), and 1-(2-hydroxyethyl)piperazine (HEP)) was added to the complex primary amine composed of monoethanolamine (MEA) and the primary amine having high steric hindrance (2-amino-2-methyl-1-propanol (AMP)), the reaction rate indicator was higher than a reference value of "1," and the absorption performance was found to be good.
Of these, N,N'-dimethylethylenediamine (DMEDA) and N,N'-dimethylpropanediamine (DMPDA), in particular, showed high reaction rate values.

Reference Signs List

12 CO₂ recovery unit
13 Industrial combustion facility
14 Flue gas
16 Flue gas cooling unit
17 CO₂ absorbent (lean solution)
18 CO₂ absorber
19 CO₂ absorbent containing CO₂ absorbed therein (rich solution)
20 Absorbent regenerator
21 Wash water

Claims

A complex amine absorbent for absorbing one or both of CO₂ and H₂S in a gas, the complex amine absorbent comprising
1) monoethanolamine (MEA), and

2) at least one primary amine having high steric hindrance selected from the group consisting of: 2-amino-1-propanol (2A1P), 2-amino-3-methyl-1-butanol (AMB), 1-amino-2-propanol (12P), 1-amino-2-butanol (1A2B), 2-amino-2-methyl-1-propanol (AMP), 2-amino-1-butanol (2A1B), with the monoethanolamine and the primary amine being dissolved in water,

3) at least one polyamine selected from the group consisting in: ethylenediamine, N,N'-dimethylethylenediamine, N,N'-diethylethylenediamine, , and N,N'-dimethylpropanediamine, or at least one of piperazine, 1-methylpiperazine, 2-methylpiperazine, 2,5-dimethylpiperazine, 1-(2-aminoethyl)piperazine, and 1-(2-hydroxyethyl)piperazine; wherein:
i)- a total concentration of the amines in the complex amine adsorbent is from 30% to 70% by weight; and

ii)- a weight ratio of the said primary amine in relation to MEA is within a range of 0.3 to 2.5.
A complex amine absorbent according to Claim 1, characterized in that
iii)- a weight ratio of said polyamine in relation to the complex of MEA and the said primary amine having high steric hindrance is 1 or less.
A method of removing one or both of CO₂ and H₂S, the method comprising: bringing a gas containing one or both of CO₂ and H₂S in contact with an absorbent to remove the one or both of CO₂ and H₂S; regenerating a solution containing one or both of CO₂ and H₂S absorbed therein; and reusing, in an absorber (18), the solution regenerated by removing the one or both of CO₂ and H₂S in a regenerator (20), wherein
the complex amine absorbent according to any one of claims 1 or 2 is used to remove the one or both of CO₂ and H₂S.
A method of removing one or both of CO₂ and H₂S according to claim 3, wherein:
a pressure inside the regenerator (20) is 130 to 200 kPa (absolute pressure),

an absorption temperature in the absorber (18) is 30 to 80°C, and

a regeneration temperature in the regenerator (20) is 110°C or higher.